Method and apparatus for logging a well using a fiber optic line and sensors

ABSTRACT

A system and method to log a wellbore, comprising a logging tool adapted to be deployed in a wellbore environment, the logging tool including at least one sensor for taking a measurement of the wellbore euviwwnent. The sensor is a fiber optic sensor and the system includes a fiber optic line in optical communication with the sensor. The data measured by the sensor is transmitted through the fiber optic line on a real time basis to the surface. Where the data is processed into a real time display. In one embodiment, the fiber optic sensor is a passive sensor not requiring electrical or battery power. In another embodiment, a continuous tube with one end at the earth&#39;s surface and the other end in the wellbore is attached to the logging tool and includes the fiber optic line disposed therein.

CROSS REFERENCE TO RELATED APPLICATIONS

This claims the benefit under 35 U.S.C. § 119(e) of the following U.S.Provisional Applications: Ser. No. 60/434,093, entitled “Method andApparatus for Logging a Well Using a Fiber Optic Line and Sensors,”filed Dec. 17, 2002; and Ser. No. 60/407,084, entitled “Optical FiberConveyance, Telemetry, and Application,” filed Aug. 30, 2002, all ofwhich are hereby incorporated by reference.

BACKGROUND

This invention generally relates to the logging of subterranean wells.More particularly, the invention relates to the logging of such wellsusing a fiber optic line and fiber optic sensors.

Prior art logging systems have been deployed via electric wireline andvia slickline. Wireline deployed logging systems are able to transmitthe data collected by the logging tool real time through the electricline. Although wireline deployed logging systems are able to transmitdata real time via the electrical wires, such systems require a greaseinjector in order to ensure that pressure from the wellbore does notescape around the wireline as it is inserted into a pressurized wellduring deployment and use. Grease injectors, however, are problematicinstruments to use, since they require great care during maintenance andoperation, have a tendency to leak under pressure and continual wear,and present an environmental hazard when such leaks occur. Moreover,wireline deployed logging systems are costly to deploy.

On the other hand, current slickline deployed lines are manufacturedfrom solid wire and are not able to transmit the logging tool data realtime to surface. Instead, slickline deployed logging systems use memorytools connected to the lower end of the line. In slickline memorylogging, the slickline and battery-powered memory tools are lowereddownhole on the end of the slickline and the memory tool is used torecord the downhole logging tool data for subsequent download andcollection at the surface once the tools are retrieved from the well.The advantages of slickline deployed systems are that they are much lesscostly and easier to deploy than wireline deployed systems, they can berun in the hole and out of the hole faster than braided wire, and theyare easier to seal against well pressure at the well head.

Most of the logging tools deployed on wireline or slickline areelectrically powered devices. Electrically powered devices includeelectronics that are very sensitive and that often become damaged in thehard environment of a subterranean wellbore. In addition, some loggingtools are memory tools and/or include downhole batteries. It is oftendifficult to shield or protect these electrical components against thehigh temperatures and pressures commonly found in a wellbore, which hightemperatures and pressures typically deteriorate and damage theelectrical components of the tools.

Thus, there exists a continuing need for an arrangement and/or techniquethat addresses one or more of the problems that are stated above. Inparticular, the prior art would benefit from a logging system that hasthe capability of transmitting the logging tool data real time tosurface, that is as economical and as easy to deploy as slicklinedeployed systems, and that does not include the detriments ofelectrically or battery powered devices.

SUMMARY

Some embodiments of the invention include a system and method to log awellbore, comprising a logging tool adapted to be deployed in a wellboreenvironment, the logging tool including at least one sensor for taking ameasurement of the wellbore environment. The sensor is a fiber opticsensor and the system includes a fiber optic line in opticalcommunication with the sensor. The data measured by the sensor istransmitted through the fiber optic line on a real time basis to thesurface, where the data can be processed into a real time display. Thefiber optic sensor can be a passive sensor not requiring electrical orbattery power. In one embodiment, a continuous tube with one end at theearth's surface and the other end in the wellbore is attached to thelogging tool and includes the fiber optic line disposed therein. Inother embodiments, the fiber optic line is embedded within a slickline,a braided optical cable, or an electro optical cable.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic of one embodiment of the logging system of thisinvention.

FIG. 2 is a schematic of another embodiment of the logging system ofthis invention.

FIG. 3 is a schematic of one embodiment of a fiber optic flow sensorincluding a spinner.

FIG. 4 is a schematic of a fiber optic casing collar locator when notactivated.

FIG. 5 is a schematic of a fiber optic casing collar locator whenactivated.

FIG. 6 is a schematic of a cross-section of a slickline including anoptical fiber.

FIG. 7 is a schematic of a cross-section of a braided optical table.

FIG. 8 is a schematic of a cross-section of an electro optical cable.

FIG. 9 is a schematic of another embodiment of a fiber optic flowsensor.

FIG. 10 is a schematic of another embodiment of a fiber optical flowsensor

FIG. 11 is a schematic of an optical fiber used in conjunction with theflow sensor FIG. 10.

FIG. 12 is a schematic of another embodiment of a fiber optic casingcollar locator.

FIG. 13 is a schematic of another embodiment of a fiber optic casingcollar locator.

FIG. 14 is a schematic of another embodiment of a spinner.

FIG. 15 is a schematic of another embodiment of a fiber optic casingcollar locator.

FIG. 16 is a schematic of an embodiment of a fiber optic tracerinjection tool.

FIGS. 17-18 are schematic of embodiments of a fiber optic spectroscopydevice.

FIGS. 19-20 are schematics of a fiber optic inclinometer.

FIG. 21 is a schematic of a fiber optic gamma ray tool.

FIG. 22 is a schematic of a fiber optic resistivity measurement tool.

FIG. 23 is a schematic of a fiber optic induction tool.

FIG. 24 is a schematic of a wavelength division multiplex (WDM)arrangement of a fiber optic system.

FIGS. 25-26 are schematics of embodiments of time division multiplexing(TDM) arrangements of fiber optic systems.

DETAILED DESCRIPTION

FIG. 1 shows the logging system 10 according to an example embodiment ofthe present invention disposed in a wellbore 5. Wellbore 5 may be cased.The logging system 10 includes at least one logging tool 12, at leastone fiber optic line 14, and at least one fiber optic sensor 17. Datacollected by the sensor 17 is transmitted real time to the surface viathe fiber optic line 14. Other data, such as tool status reports (i.e.,active/not active, malfunctioning, status), may also be sent from thelogging tool 12 through the fiber optic line 14 to the surface on a realtime basis.

Sensor 17 may include but are not necessarily limited to a pressuresensor 22, a flow sensor such as spinner 26, a chemical properly sensor28, or a casing collar locator 30. Each sensor 17 collects its data, anda signal representative of the data is transmitted via the optical fiber14. Sensors 17 may also include other fiber optic data gathering toolsor sensors, including optical fluid analyzers, gamma ray tools,temperatures sensors, chemical property sensors, gyro tools, waterdetection sensors, gas detection sensors, oil detection sensors,acoustic sensors, differential pressure sensors, spectrometers,inclinometers, relative bearing sensors, distributed temperaturesensors, distributed strain sensors, distributed pressure sensors,hydrophones, accelerometers, sonic tools, resistivity sensors, orinduction sensors, to name a few.

In this application, the term “logging tool” is a tool that measures atleast one parameter of the wellbore, wellbore environment, wellborefluids, or formation (collectively referred to as “wellboreenvironment”). Likewise, the term “logging” is the taking ofmeasurements of at least one parameter of the wellbore environment.Logging can occur while the tools are held stationary at a given depthor while the tools are moved up and down in the wellbore whilesimultaneously gathering data and transmitting the data to the surfacethrough at least one optical fiber. It is understood that the term“logging tool” may include a plurality of sensors, each of which maymeasure a different parameter. In addition, a plurality of logging tools12, which with at least one or a plurality of sensors 17, may also beused with some embodiments of this invention.

Sending information on a “real-time basis” or “in real time” refers tosending the information as measurements or other events are occurring.However, “real time” does not require that the information be sentimmediately after collection—some delay (due to processing, storage, orother tasks) can occur between collection and transmission). Sendinginformation in real time is distinguished from collecting informationwith a downhole tool in a well, storing the information in the downholetool, retrieving the downhole tool to the well surface, and offloadingthe stored information from the tool to surface equipment.

In one embodiment, the fiber optic line 14 is disposed within a conduit32, which may protect the fiber optic line 14 from the harsh wellborefluids and environment. Conduit 32 also protects fiber optic line 14from strain that may otherwise be induced during the deployment, loggingand recovery operations of the tools and optic fiber tube. Logging tool12, as well as sensors 17, may be attached to the conduit 32; therefore,the fiber optic lie 14 located within the conduit 32 does not bear thefull weight of the logging tool 12. In one embodiment, conduit 32 is asmall diameter tube, such as 3/16 inches, that has a wall thicknesslarge enough to support the logging tool 12 in addition to the weight ofthe tube and optic fibers disposed therein. In another embodiment,conduit 32 is a coiled tubing string 37 (as shown in FIG. 2), with thefiber optic line(s) 14 disposed therein. In another embodiment (notshown), small diameter conduit 32 may be deployed within a coiled tubingstring.

In one embodiment, conduit 32 may be deployed on a reel such that thetube, optical fibers, and tools can be recovered a plurality of timesfrom wells. The tools can subsequently be disconnected at surface, andthe reel with the tube and optic fibers can thus be transported to otherwells where tools can be reconnected to the tube and then re-deployed ina different well. In one embodiment, conduit 32 is a continuous tubethat extends from the surface to the downhole logging tool(s) 12.

Wellhead 34 is located at the top of wellbore 5. Conduit 32 with fiberoptic line 14 therein is passed through a stuffing box 36 or a packingassembly located on wellhead 34 as well as a lubricator 70. Stuffing box36 provides a seal against conduit 32 so as to safely allow thedeployment of logging system 12 even if wellbore 5 is pressurized.

Conduit 32 may be deployed from a reel 38 that may be located on avehicle 40. Several pulleys 42 may be used to guide the conduit 32 fromthe reel 38 into the wellbore 5 though the stuffing box 36, lubricator70, and wellhead 34. Based on the size of the conduit 32, deploymentdoes not require a coiled tubing unit (if conduit 32 is not a coiledtubing or is not deployed within a coiled tubing) nor a large winchtruck. Reel 38, in one example implementation, has a diameter ofapproximately 22 inches. Being able to use a smaller reel and vehiclethan conventional coiled tubing reels and vehicles with electrical andbraided wire deployment logging systems dramatically reduces the costsof the operation. In the embodiment using a coiled tubing string, reel38 has a diameter appropriate to accommodate such coiled tubing and thedeployment and recovery equipment is the same as that use with coiledtubing deployment and recovery.

Fiber optic line 14 is connected to an acquisition unit 44 that isnormally located at the surface and may be located in the vehicle 40.Acquisition unit 44 receives the optical signals sent from the loggingtool 12 through the fiber optic line 14. Acquisition unit 44, whichwould typically include a microprocessor and an opto-electronic unit,delivers the data (the optical signals) to a processor, which processesthe data and enables the presentation of the data to a user at surface.Delivery to the user can be in the form of graphical display on acomputer screen or a print out or the raw data transmitted from thelogging tool 12. In another embodiment, acquisition unit 44 is acomputer unit, such as a laptop computer, that plugs into the fiberoptic line 14. In another embodiment, the data is transmitted at surfaceto a network, such as the Internet, and presented to users via a portionon the network. The surface acquisition unit 44 processes the opticalsignals or data from the downhole logging tools and optical fiber toprovide the chosen data output to the operator. The processing caninclude data filtering and analysis to facilitate viewing of the data.

An optical slip ring (rotary connection) 39 is functionally attached tothe reel 38 and enables the connection and dynamic optical communicationbetween the fiber optic line 14 and the acquisition unit 44 while thereel is turning and running the tube into the well or pulling the tubeout of the well. The optical slip ring 39 interfaces between the fiberoptic line 14 that is turning with the reel and the stationary opticfiber at the surface. The slip ring 39 thus facilitates the transmissionof the real tie optical data between the dynamically moving optic fiberinside the moving reel 38 and the stationary acquisition unit 44 atsurface. In short, the slip ring 39 allows for the communication ofoptical data between a stationary optical fiber and a rotating opticalfiber.

In one embodiment, a plurality of fiber optic lines 14 are disposed inconduit 32. The use of more than one fiber line 14 provides redundancyto the real time transmission of the data from the logging tool 12 tothe surface, ability to use multiple logging tools, as well as increasedoptical power transmission to down hole tools and other device such aspower sources. The use of more than one fiber optic line 14 also allowsfor both single and multimode optical fiber to be run.

In another embodiment as shown in FIG. 6, instead of being deployedwithin a conduit 32, the optical fiber 14 is embedded within a slickline100. Slickline 100 protects optical fiber 14 from the harsh wellborefluids and environment. Logging tool 12, as well as sensors 17, areattached to the slickline 100; therefore, the optical fiber 14 does notbear the full weight of the logging tool 12. The deployment equipmentincluding wellhead equipment required for use with slickline 100 is thesame as for prior art slickline operations, including reels,lubricators, etc.

In another embodiment as shown in FIG. 7, the optical fiber 14 isembedded within a braided cable typically composed of at least one (andtypically more than one) layer of braids 102, such as steel braids and afiller material 104 within the braid layers 102. The filler material 104protects at least one and sometimes a plurality of optical fibers 14located therein. Braid layers 102 and filler material 104 protectoptical fiber 14 from the harsh wellbore fluids and environment. Loggingtool 12, as well as sensors 17, are attached to the braid layers 102;therefore, the optical fiber 14 does not bear the full weight of thelogging tool 12.

In another embodiment as shown in FIG. 8, the optical fiber 14 isembedded within an electro-optical cable, which is similar to thebraided cable of FIG. 7. However, in this embodiment, at least onelectrical conductor 106 is included with the optical fibers 14. Theconductors 106 carry electricity to and from any electrically powereddownhole tools that may be part of the logging tool 12. In oneembodiment, the conductors 106 can also be used for purposes oftelemetry and/or communication.

In one embodiment as shown in FIG. 1, each of the sensors 17 is apassive fiber optic sensor. In this embodiment, an optical transmitter20 is located at the surface (in vehicle 40, for instance) and amodulator 48 may be located downhole. The surface optical transmitter 20sends an optical signal, which may be in the form of pulses, down thefiber optic line 14 to the sensors 17. In the embodiment including themodulator 48, the modulator 48 modulates the optical signal sent fromthe surface optical transmitter 20 in a way that transmits the relevantdata from the sensor 17. Typically, the modulator 48 changes a propertyof the optical signal, such as intensity, frequency, polarization state,coherence, or phase. In other words, the modulated signal effected bythe modulator 48 becomes the optical signal with the data. Acquisitionunit 44 (at the well surface) receives the modulated signal and convertsit back into the sensor 17 data. In one embodiment, each sensor 17 hasits own modulator 48. In another embodiment, one modulator 48 isassociated with all of the sensors 17. In another embodiment notincluding a modulator 48, the sensor 17 reflects a return optical signalback to the acquisition unit 44 with the relevant measurement encodedtherein. The relevant measurement is encoded in the return opticalsignal based on the interaction of the sensor 17 with the wellboreparameter being sensed. The data is typically encoded as a change inintensity, frequency, polarization state, coherence, or phase.

In another embodiment (not shown), an optical transmitter may be locateddownhole. In this embodiment, the downhole optical transmitter sends theoptical signals through the fiber optic line 14 and to the acquisitionunit 44 depending on the measurements take by the tools. In thisembodiment, the downhole optical transmitter may be linked to a downholebattery for power.

In one embodiment, modulator 48 may be a reflector, such as a mirror orfiber grating.

Sensor 17 may include a spinner 26, as shown in FIG. 3. In thisembodiment, modulator 48 may be part of the spinner 26. The blades 31 ofthe spinner 26 are located external to main housing 33 of the spinner26, with the stem 27 connected to the blades 31 rotatably mounted withrespect to the spinner housing 33. A disc 29 is also attached to thestem 27 inside the spinner housing 33, which disc 29 rotates along withstem 27 and spinner 26. The modulator 48 is positioned on the disc 29 sothat it passes along the path of the surface-sent optical signal in thefiber optic line 14 once every revolution of the disc 29/blades 31.Thus, modulator 48 modulates the optical signal, for example, once everyrevolution of the disc 29/blades 31. Acquisition unit 44 receives themodulated signal (in this case a reflected pulse) and based on thefrequency of reception is able to calculate the revolutions per minuteof the blades 31. With this calculation, acquisition unit 44 is thenable to calculate the flow of the fluids or other condition in thewellbore 12 that causes the spinner 26 to rotate. Thus, the spinner 26serves as a passive fiber optic flow sensor.

FIG. 14 shows another embodiment of a spinner 26 that is similar to thatshown in FIG. 3. The difference is that in the embodiment of FIG. 14 thedisc 29 is sealed within the housing 33 and the blades 31 are sealedoutside the housing 33 in order to prevent wellbore fluids from enteringthe housing 33 and contaminating or deteriorating the optical fiber 14and optical fiber reading components. Essentially, stem 27 of the FIG. 3embodiment is replaced with a magnetic coupling 200 between a magneticdisc component 202 and a magnetic blade component 204. The magneticcomponents 202, 204, each of which may include a permanent magnet, areconstructed and configured so that rotation of the magnetic bladecomponent 204 induces rotation of the magnetic disc component 202. Inone embodiment, the magnetic blade component 204 has a cup shape, themagnetic disc component has a rod shape, and the housing 33 extendsthere between and thus also has a cup-shape in such interval. Themodulator 48 and acquisition unit 44 function in similar fashion as theFIG. 3 embodiment.

In another embodiment, the modulator 48 on the disc 29 is omitted.Instead, a mirror is placed behind the disc 29 such that the disc 29 isinterposed between the optical fiber 14 and the mirror. The disc 29 hasone or more openings such that as the disc 29 rotates, an opening isintermittently aligned with the optical fiber 14 and the mirror to allowlight from the optical fiber 14 to pass through the opening to themirror and reflected light to pass through the opening from the mirrorback to the optical fiber. This effectively provides a shutter effect,where the mirror is intermittently exposed to light from the opticalfiber 14. The rotational speed of the disc 29 determines the frequencyat which light is reflected from the mirror back to the optical fiber.

FIG. 9 shows another embodiment of a spinner 26. In this embodiment, apermanent magnet 110 is attached to the rotating stem 27. A fixed coil112 is attached to the interior of the housing 33. The magnet 110 andcoil 112 are placed and configured so that the two come into a magneticcoupling or connection, for example, once every revolution of blade31/stem 27. Each time the magnet 110 and coil 112 become magneticallycoupled, the electrical signal generated by such coupling or connectionis sent through a conductor 114 to a voltage amplifier 116. The voltageamplifier 116 amplifies the voltage, which is then passed on to apiezoelectric material 118 that is mechanically coupled to the opticalfiber 14. Voltage imparted to the piezoelectric material 118 causes thematerial 118 to constrict, creating a strain on optical fiber 14. Thus,the optical fiber 14 is placed under strain once for every revolution ofblade 31. For this embodiment, at least one Fiber-Bragg Grating (FBG)119 may be incorporated into the optical fiber 14.

The FBG 119 shifts the reflected wavelength of the optical signal beingsent downhole each time strain is applied to optical fiber 14. Thewavelength shift is then detected at the surface by the acquisition unit44, which information can be used to determine the revolutions per unittime of the blades 31, thereby enabling the determination of the flowrate of the fluid propelling the blades 31. Instead of usingpiezoelectric material 118, a piezoelectric coating may be applied tooptical fiber 14 in order to supply the required strain. In thisembodiment, the FBG 119 can be part of the modulator 48. Alternatively,a fiber interferometer may be used instead of an FBG.

FIGS. 10 and 11 show another embodiment of a spinner 26. This embodimentis similar to that shown in FIG. 3. However, in this embodiment,modulator 48 is incorporated on the side 35 of disc 29. Optical fiber 14is placed between the disc side 35 and the housing 33. In oneembodiment, the optical fiber 14 is cut at a slanted angle (e.g., 45°angle) at its end (FIG. 11) in order to project optical signals in thedirection of the disc side 35.

Sensor 17 may also include a casing collar locator 30, as shown in FIGS.4 and 5. In this embodiment, casing collar locator 30 includes amagnetic component 31 that is activated each time it passes by a casingcollar 33. FIG. 4 illustrates the casing collar locator 30 when themagnetic component 31 is not activated. As shown in FIG. 5, the locator30 is arranged so that each time the magnetic component 31 is activated,the modulator 48 is activated or moved to modulate the optical signalsent down the fiber optic line 14. For instance, the modulator 48 may beactivated to come in line with fiber optic line 14 and reflect back theoptical signal each time the magnetic component 31 senses a casingcollar 35. Thus, the acquisition unit 44 receives the modulated signal(a reflected pulse) each time the locator 30 passes a casing collar 33.The acquisition unit 44 then identifies the location of casing collars33 passed by the logging tool 12.

FIG. 12 shows another embodiment of a casing collar locator 30. In thisembodiment, a permanent magnet 120 and a coil 122 are fixedly mounted inthe interior of housing 124. Optical fiber 14 may pass through themagnet 120 and coil 122, both of which can be annular in shape. As thecasing collar locator 30 is deployed in a wellbore, it will pass anumber of casing collars. Each time the locator 30 passes a casingcollar, the casing collar and the magnet 120 and coil 122 will becomemagnetically coupled, which causes generation of an electric signal thatis sent through a conductor 126 to a voltage amplifier 128. The voltageamplifier 128 amplifies the voltage, which is then passed on to apiezoelectric material 130 that is mechanically coupled to the opticalfiber 14. Voltage imparted to the piezoelectric material 130 causes thematerial 130 to constrict creating a strain on optical fiber 14. Thus,the optical fiber 14 is placed under strain once for every casing collarthat is sensed. For this embodiment, at least one Fiber-Bragg Grating(FBG) 132 may be incorporated into the optical fiber 14. The FBG 132shifts the reflected wavelength of the optical signal being sentdownhole each time strain is applied to optical fiber 14. The wavelengthshift is then detected at the surface by the acquisition unit 44, whichinformation can be used to identify the location of the sensed casingcollars. Instead of using piezoelectric material 118, a piezoelectriccoating may be applied to optical fiber 14 in order to supply therequired strain. In this embodiment, the FBG 119 can be part of themodulator 48.

FIG. 13 shows another embodiment of casing collar locator 30. Thisembodiment includes a permanent, fixed magnet 140 and a moving magnet142. The fixed magnet 140 and moving magnet 142 are configured so thatthe moving magnet 142 moves in relation to the fixed magnet 140 eachtime the locator 30 passes a casing collar and a magnetic connection orcoupling is created between the casing collar and the magnets 140, 142.The moving magnet 142 is fixed to a component 144 that includes amodulator 48. The modulator 48 may include alternately disposed blackand white lines. Optical fiber 14 is disposed within housing 146 so thatits end faces the side of component 144 and the modulator 48. Theoptical fiber 14 end is cut so that the optical signals are directedtowards the modulator 48, as shown in FIG. 11. When moving magnet 142moves, so does the modulator 48, which causes the black and white linesto also shift in relation to the optical fiber 14. The shift andmovement in the black and white lines causes the reflected opticalsignal to also be modulated. Therefore, at the surface, an operator canidentify the location of a casing collar each time the acquisition unitreceives a reflected optical signal that is thus modulated. A spring 148may be used to maintain moving magnet 142 and component 144 in a staticposition. Instead of black and white lines, the modulator 48 can includeprofiles of other color or shapes to provide indication of movement.

Alternatively, the modulator 48 of FIG. 13 can be a plate with one ormore openings, with the plate being moveable by movement of the movingmagnet 142. A mirror is aligned with respect to the end of the opticalfiber, and the plate is provided between the mirror and the opticalfiber. As the plate moves, an opening in the plate lines up with themirror and the optical fiber end such that light can pass through theopening from the optical fiber to the mirror, and reflected light canpass from the mirror to the optical fiber through the opening. Thiseffectively provides a light shutter effect controlled by movement ofthe moving magnet 142 where transmitted light (from the optical fiber)and reflected light (from the mirror) is allowed to intermittently passthrough the opening of the moving plate.

FIG. 15 shows another embodiment of the casing caller locator 30, whichincludes a permanent magnet 150 that generates magnetic fields indicatedas 152. The optical fiber 14 is coated with a magneto-strictive coating,which is formed of a magneto-strictive material (e.g., nickel). In thepresence of a strong magnetic field, the magneto-strictive materialshrinks slightly in the direction of the field. The shrinking of themagneto-strictive coating causes strain to be applied onto the opticalfiber 14, which incorporates an FBG 154 to shift the reflectedwavelength of an optical signal in response to strain applied to theoptical fiber 14 by the magneto-strictive coating.

Various other types of fiber optic measurement, sensing, andtransmission techniques may be used with the system, depending on thetype of sensor 17. For instance, chemical sensors may include fiberoptic lines doped or coated with a particular reactant that reacts onlywhen it comes into contact with a target fluid or chemical (such assulfur, water, or hydrogen sulfide). The reaction of the reactant thencauses a specific change on the fiber optic line 14 which in turn causesa specific change ion the optical signal being returned by the sensor 17from the downhole environment to the surface through the fiber opticline 14 (such as a change in intensity, frequency, polarization state,or phase). Acquisition unit 44 receives this return optical signal anddiscerns the relevant information from the sensor 17 by identifying thespecific change imparted by the sensor 17 on the return optical signal.Fiber optic pressure sensors function in similar ways.

The fiber optic line 14 also allows a distributed temperaturemeasurement to be taken along the length of the fiber optic line 14 orthe plurality of optic fiber lines disposed inside the conduit 32 (FIG.1). Generally, pulses of light at a fixed wavelength are transmittedfrom the optical transmitter 20 through the fiber optic line 14. Lightis back-scattered within fiber optic line 14 and returns to the surfaceequipment 44. Knowing the speed of light and the moment of arrival ofthe return signal enables its point of origin along the fiber line 14 tobe determined. Temperature stimulates the energy levels of the silicamolecules in the fiber line 14. The back-scattered light containsupshifted and downshifted wavebands (such as the Stokes Raman andAnti-Stokes Raman portions of the back-scattered spectrum), which can beanalyzed to determine the temperature at origin. In this way thetemperature of each of the responding measurement points in the fiberline 14 can be calculated by the equipment 44, providing a completetemperature profile along the length of the fiber line 14. The fiberoptic line 14 is connected to a distributed temperature measurementsystem receiver, which can be a unit within the acquisition unit 44 andwhich can be an optical time domain reflectrometry unit. The fiber opticline 14 can be used concurrently as a transmitter of data from thelogging tool 12, a transmitter of downhole tool activation signals (aswill be described), and as a sensor/transmitter of distributedtemperature measurement. In another embodiment, fiber optic line 14 maybe used to take a distributed strain measurement along the length of thefiber optic line(s)

14. The fiber optic line(s) 14 may also be used to support other sensingtechniques, such as distributed or multipoint strain and/or temperature,or even an acoustic array.

It is noted that if more than one sensor 17 is used in the logging tool12, the fiber optic line 14 may have to be split into a plurality offiber optic lines, each being connected to a different sensor 17. Eitherwavelength division multiplexing (WDM) or time division multiplexing(TDM) may be used to interrogate the sensors 17 in this configuration.Optical couplers may also be used to facilitate this configuration. Inanother embodiment, a separate fiber optic line 14 is used for eachsensor 17, with each fiber optic line 14 being disposed in the conduit32.

In one embodiment, conduit 32, with fiber optic line 14 therein, mayalso be used to actuate downhole devices. Conduit 32 may be pressurizedwith a fluid, wherein the pressurized fluid actuates downhole tools suchas a packer 50 or a perforating gun 52 (see FIG. 2). The activationsignal may be applied pressure sent through conduit 32 above a certainthreshold or pressure pulses with a specific signature. The downholetool includes a signal receptor, such as a ratchet mechanism, shearpinned firing head, or a pressure transducer, which receives theactivation signal and activates the downhole tool if the correct signalis received by the receptor. For instance, packer 50 may actuate to gripand seal against the wellbore walls, or thereafter, to ungrip and unsealfrom the wellbore walls. Also, perforating gun 52 may actuate to shootthe shaped charges 55 and create perforations 54 in the wellbore. Otherdownhole tools that may be activated include flow control valves,including sleeve valves and ball valves, samplers, sensors, pumps, ortractors.

In another embodiment, the downhole tools described above may beactivated by optical signals sent through the fiber optic line 14(instead of pressure signals sent through the conduit 32). In thisembodiment, the downhole tool is functionally connected to the fiberoptic line 14 so that a specific optical signal frequency, signal,wavelength or intensity activates the downhole tool. A photovoltaicconverter can be used to facilitate the reception of the optical signaland conversion of the optical signal into activation energy for downholetools. Such photovoltaic converters can convert optical energy intoelectrical or even mechanical energy. In another related embodiment, thedownhole tool is connected to a fiber optic line 14 that is not used forlogging data transmission to the surface.

In another embodiment, pressure pulses through the conduit 32 andoptical signals through a fiber optic line 14 can both be sent toactivate the downhole tools. In one embodiment, pressure pulses throughthe conduit 32 and optical signals through a fiber optic line 14 can besent simultaneously to activate different downhole tools. In anotherembodiment, data in the form of optical signals can be transmittedthrough the fiber optic line 14 at the same time pressure signals aretransmitted through the conduit 32. In yet another embodiment, data inthe form of optical signals and activation commands in the form ofoptical signals can be sent simultaneously through the fiber optic line14.

The attached figures show the use of logging system 10 is a land well.However, logging system 10 can also be used in offshore wells onplatforms or located subsea.

In operation and in relation to FIGS. 1 and 2, an operator firstconnects stuffing box 36 and lubricator 70 on top of wellhead 34 andbegins to deploy conduit 32 from the reel 38 and into wellbore 5. Aspreviously stated, the stuffing box 36 seals against the outside wall ofthe conduit 32 enabling the deployment of the logging system 10 in awellbore 5 that is pressurized. In general, the logging tool 12 islowered to the appropriate depth in the well and the sensors 17 taketheir relevant readings as the tools are moved in the well. In anotherembodiment the tools are held stationary and data is gathered whilst thetubing, tools, and optic fiber are stationary in the well. In theembodiment in which the fiber optic line 14 is deployed after theconduit 32 is in place, the pump 46 is activated and the pumped fluidacts to drag the fiber optic line 14 down the conduit 32.

The surface optical transmitter 20 sends an unmodulated signal to thelogging tool 12. In the embodiment including a modulator 48, themodulator 48 modulates the signal so as to encode the data onto thesignal that returns to the acquisition unit 44. In the embodiment notincluding a modulator 48, the sensor 17 reflects a return optical signalback to the acquisition unit 44 with the relevant measurement encodedtherein. In either case, the data measured by the logging tool 12 issent to the acquisition unit 44 in real time.

Logging tool 12 may be lowered so that spinner 26 and the other sensors17 are adjacent perforations 54 and formation 57 so as to obtainaccurate and real time data of the parameters adjacent to suchperforations 54 and formation 57. In the embodiment in which the fiberoptic line 14 is also used as a distributed temperature measurementsystem, the distributed temperature measurements may be used toapproximately determine flow along the length of the wellbore 5(including across different perforations), since flow acts to change thetemperature along the wellbore and hence the fiber optic line 14.Furthermore, this inferred distributed flow profile along the well cansubsequently be correlated with the spinner logging tool located on thelower end of the conduit 32. Using the distributed temperaturemeasurement to approximately determine flow indicates to an operatorwhich areas or perforations in the wellbore 5 should be correlated withthe logging tool 12, such as by taking the real flow measurement usingspinner 26. Casing collar locator 30 may be used to identify thelocation of casing collars and therefore determine the depth of thelogging tool 12.

The downhole tools, such as packer 50 and perforating gun 52, may beactivated at any point by way of pressure signals or hydraulicallytransmitted energy through the conduit 32 or optical signals through afiber optic line 14. Having the ability to perforate a formation andthen log the relevant formation in the same trip saves time and money.

Once the logging operation is completed, the logging tool 12 is raisedby reversing reel 38. It is appreciated that reel 38 and the relativesize of conduit 32 enables the repeated and simple deployment andretrieval of logging tool 12. Placing reel 38 on vehicle 40 or otherwisemaking the reel portable enables the logging system 10 to be used inmultiple wellbores.

By use of an all-optical system (fiber optic transmission line 14 andsensors 17) in some embodiments, the detriments of electrical devicesare avoided. This is particularly helpful in high-temperature,high-pressure wells, such conditions being extremely harsh onelectrically powered devices. Compared to electrical tools, additionalbenefits of an all optical system include that optical tools are muchless susceptible to shock or vibrations encountered duringtransportation to or deployment within a wellbore, optical tools arelighter, and optical tools may cost less. In other embodiments, bothoptical and electrical components are used.

According to another embodiment, a tracer injection tool 300 (shown inFIG. 16) can be controlled by using an optical fiber 302. The end of theoptical fiber 302 is coupled to a converter 304 that converts lightenergy to electrical or mechanical power. Optionally, a filter 304 isprovided to filter out undesired optical signals, such as opticalsignals that are not of a particular wavelength or wavelengths. Theconverter 304 is coupled to a valve 306 to control operation of thevalve 306. The valve 306 controls communication through a port 308 thatextends through a housing 310 of the tracer injection tool 300. In theclosed position shown in FIG. 16, the valve 306 prevents tracer fluidfrom flowing from a channel 314 through the port 308 to the outsideenvironment. The tracer fluid is contained in a chamber 312 that isdefined by the housing 310, a wall 316, and a piston 318.

The piston 318 is moveable along a longitudinal direction (indicated asL) of the tracer injection tool 300. A spring 320 applies a forcesagainst the piston 318 to apply pressure against the tracer fluid withinthe chamber 312. Optionally, a port 322 is provided to enable outsidewellbore pressure to be communicated into a chamber 324 in which thespring 320 is located. The outside wellbore pressure applies ahydrostatic pressure against the piston 318. The spring 320 ispositioned between the piston 318 and a fixed wall 326.

In operation, in response to an optical signal transmitted down theoptical fiber 302, the converter 304 converts the signal to cause thevalve 306 to open to allow the tracer fluid in the channel 314 to flowout of the port 308 into the surrounding wellbore environment. Thetracer injection tool 300 is lowered to a specific wellbore interval, atwhich point the valve 306 is opened to inject the tracer fluid into thewellbore fluid. This allows a well operator to track fluid flow withinthe wellbore.

A modified version of the tool shown in FIG. 16 can be used to collect asample. In a sampler, instead of a spring 320 to apply a force againstthe moving piston 318, an atmospheric chamber can be provided in placeof the spring 320, such that when the valve 306 is opened, the outsidewellbore fluid will cause the piston 318 to move against the atmosphericchamber to enable wellbore fluid to enter the chamber 312. After thesample of fluid is collected, the valve 306 can be closed (in responseto an optical signal transferred down the optical fiber 302 and receivedby the converter 304).

Alternatively, a fiber optic sampler does not include a moveable pistonas in the fiber optic sampler discussed above. Instead, the samplerincludes a bottle or other chamber that contains a vacuum. When a valvecontrolled by an optical signal communicated down the optical fiber isopened, wellbore fluid rushes into the bottle, after which the valve canbe closed.

According to another embodiment, a spectroscopy tool 400 includes anoptical fiber 402 and a channel or chamber 404 that contains a fluid tobe analyzed by use of spectroscopy. The optical fiber 402 has a firstsegment 404 that is coupled by a coupler 406 to a second optical fibersegment 408. The second optical fiber segment 408 is coupled to thefluid channel or chamber 404, and a third optical fiber segment 410 iscoupled to the other side of the fluid channel or chamber 404. A delayelement 412 is optionally provided in the third optical fiber segment410 to provide some type of delay to light returning back to thesurface.

In operation, incoming light is transmitted over the optical fiber 402that is transferred from the optical fiber segment 404 to the secondoptical fiber segment 408. The incoming light passes through the fluidchannel or chamber 404. Different types of fluid absorb or attenuatelight at different wavelengths differently. After passing through thefluid channel or chamber 404, the attenuated or modulated light proceedsthrough the optical fiber segment 410, passes through the delay element412 (if present) and is communicated through the coupler 406 back to thefirst optical fiber segment 404. The attenuated or modulated light istransmitted up the optical fiber 402 back to the surface.

In a different embodiment of a spectroscopy tool, shown in FIG. 18,instead of using the arrangement of FIG. 17, an optical fiber 420 isattached at its end to a fluid channel or chamber 422. A mirror or othertype of reflective device 424 is provided on the other side of the fluidchannel or chamber 422. Light transmitted down the optical fiber 420passes through the fluid in the channel or chamber 400, and is reflectedback by mirror or other reflective device 424 back through the channelor chamber 422 and back to the optical fiber 420. The attenuated light(which has passed through the channel or chamber 422 twice) istransmitted back to the surface for processing.

In yet another embodiment, a refraction measurement tool is provided byplacing an end of the optical fiber into a fluid. Light is transmittedthrough the optical fiber into the fluid. The amount of light reflectedby the fluid is proportional to the index of refraction of the fluid inrelation to the optical fiber or to an optical window in front of theoptical fiber. The measured index of refraction provides an indicationof the type of fluid (e.g. gas or liquid).

According to yet another embodiment, FIG. 19 shows an inclinometer 440to detect the inclination of a tool string in which the inclinometer 440is attached. The inclinometer 440 includes a mass 442 that is attachedto optical fiber segments 444, 446, and 448 (FIG. 20). The other side ofthe mass 442 is also connected to optical fiber segments in similarfashion. The optical fiber segments 444, 446, and 448 may be part of thesame optical fiber, or part of different optical fibers. To enable theoptical fiber segments to be attached to the mass 442 in the mannerdepicted in FIGS. 19 and 20, a single optical fiber is threaded throughthe mass 442 and an opening in a wall 451. The optical fiber is looped(at 450) back and threaded through the wall 451 and through the mass 442at a different location. The threading is repeated to provide themultiple fiber optic segments depicted in FIGS. 19 and 20. The mass 442and attached optical fiber segments are located in a chamber 452 definedby the housing 454 and walls 456 and 452.

FBGs 458, 460, and 462 are provided on each of respective fiber opticsegments 444, 446, and 448. Different orientations of the mass 442 causedifferent strains to be applied on the optical fiber segments, 444, 446,and 448, which in turn cause the FBGs 458, 460, and 462 to modulate theoptical signals passing through respective signals differently.

In yet another embodiment, it is possible to optically identify theposition of the main axis of a tool in relational to the magnetic force.This can be performed by using magneto-strictive materials, opticallyinterrogating a compass or magnetically interrogating a compass andencoding the signal to a fiber in a manner similar to the casing callerlocators described above.

FIG. 21 shows a gamma ray detector 600 that includes a housing 602containing a scintillating crystal 604 and an optical fiber segment 606.The scintillating crystal 604 converts gamma ray photons into opticalphotons. However, the photons produced by the scintillating crystal 604are shorter wavelength signals than the infrared band of signals thatare transmitted through optical fibers. In accordance with someembodiments of the invention, the optical photons produced by thescintillating crystal 604 are converted by a detector 608 to either enelectrical signal or to an optical signal. If converted to an opticalsignal, the optical signal is suitable for transmission over the opticalfiber 606 back to the surface. However, if the detector 606 converts theoptical photons from the scintillating crystal 604 to an electricalsignal, the electrical signal is provided to an optical transmitter ormodulator 610. If a modulator, the transmitted optical signalcommunicated from the surface down the optical fiber 606 to themodulator 610 is changed or modulated in some manner and reflected backto the surface. However, if an optical transmitter is used, then theelectrical signal provided by the detector 608 is used to control theoptical signal generated by the optical transmitter and transmitted backto the surface over the optical fiber 606.

According to further embodiments, a resistivity measurement tool 620includes a housing 622 that contains optical fibers 624 and 626, as wellas electrodes 628, 630, 632, and 634 for measuring the resistivity ofthe surrounding formation. The optical fiber 626 receives transmittedlight from a surface, with the transmitted light received by a detector628 that converts the optical signal to electrical signal. Theelectrical signal is provided to electrodes 628 and 634, which generatea current into the surrounding formation. The current is received byelectrodes 630 and 632, with the current having a characteristicdetermined by the resistivity of the surrounding formation. The currentreceived by the electrode 630 and 632 is converted to electrical voltagethat drives a piezoelectric (PZT) element 636. The piezoelectric element636 is provided adjacent an optical interferometer 642 that is locatedbetween two FBGs 638 and 640. The optical interferometer 642 causes achange in the path length of the optical signal in the optical fiber624. This modulating enables surface equipment to detect the resistivityof a formation that is being tested. In addition to measuring formationresistivity, the tool 620 can also be used to determine water volumefraction estimation in multi-phase flows, corrosion surveillance, andothers.

In another implementation as shown in FIG. 22, instead of usingelectrodes to measure resistivity or other characteristics, inductioncoils 650, 652, 654, and 656 are employed. In this embodiment, anoptical fiber 658 transmits light down to the end of the optical fiber,which is received by a detector 655. The detector 655 converts theoptical signals to electrically signals, which cause the induction coilsto generate magnetic fields. The generated magnetic fields havecharacteristics that depend on the resistivity of the surroundingformation. The magnetic fields are detected by induction coils 650 and652, which are coupled to a piezoelectric element 660. The piezoelectricelement 660 modulates an optical interferometer 662 provided betweenFBGs 664 and 666. This modulation is thus controlled by magnetic fieldsthat depend upon resistivity of the surrounding formation.

In other embodiments, optical fiber technology can be used in otherapplications. For example, an array of FBG sensors can be added to anoptical fiber to provide multi-point temperature, strain, pressure,acoustic pressure, and a variety of other measurements. Alternatively,optical fiber gyroscopes can be used to aid the navigation intocomplexed wells. Also, several kinds of optical hydrophones andaccelerometers can be used.

In yet another application, a combination of hydrophones oraccelerometers with piezoelectric transducers powered by light togenerate an acoustic signal, such as a “ping,” can be used. This enablesthe implementation of a sonic tool to measure sound velocities, as anexample.

To enhance flexibility, an array of sensors or other devices can becoupled to an optical fiber, with filters provided to enable each sensoror device to operate at a different wavelength. For example, as shown inFIG. 24, an optical fiber 800 is coupled to a multiplexer/demultiplexer802. The multiplexer 802 effectively contains filters to route anoptical signal having a first wavelength (λ₁) over a first optical fibersegment 804, an optical signal having a second wavelength (λ₂) over asecond optical fiber segment 806, an optical signal of a thirdwavelength (λ₃) over a third optical fiber segment 808, an opticalsignal having a fourth wavelength (λ₄) over a fourth optical fibersegment 810, and a fifth optical signal having a fifth wavelength (λ₅)over a fifth optical fiber segment 812. Different sensors or devices canbe connected to the different optical fiber segments 804, 806, 808, 810,and 812, to enable these devices to operate at different wavelengths.

FIG. 25 shows a time division multiplexing (TDM) arrangement in which apulse of light is used to interrogate multiple sensors or devices. TDMrelies upon sending optical signals to different sensors and devices atdifferent times. As shown in FIG. 26, this is accomplished by providingdelay elements 820, 822, and 824 along a length of optical fiber 826.Splitters 828, 830, 832, and 834 are coupled to respective devices orsensors to route an optical signal to such devices or sensors. Thus, anoptical signal that is transmitted from the well surface is provided tothe sensor or device coupled to the first splitter 828. This signal isdelayed by the delay element 820, with the first delayed optical signalpassed by the coupler 830 to its respective sensor or device. This isrepeated for the remaining delay elements and couplers.

FIG. 26 shows a different TDM arrangement, in which optical signalreceived and fiber optic segment 840 is coupled to four segments 842,844, 846, and 848. The first optical fiber segment 842 does not have adelay element. The second optical fiber segment has one delay element850. The third optical fiber segment 846 includes two delay elements852. The third optical fiber segment 848 includes three delay elements854.

While the invention has been disclosed with respect to a limited numberof embodiments, those skilled in the art, having the benefit of thisdisclosure, will appreciate numerous modifications and variationstherefrom. It is intended that the appended claims cover all suchmodifications and variations as fall within the true spirit and scope ofthe invention.

1-138. (canceled)
 139. A fiber optic flow sensor adapted to be disposedin a wellbore, comprising: a fiber optic line carrying an opticalsignal; a spinner adapted to spin when in contact with fluids flowingthrough the wellbore; and a modulator functionally connected to thespinner, the modulator modulating the optical signal depending on thespinning of the spinner.
 140. The sensor of claim 139, wherein themodulator is located on the spinner and the spinner and modulator areconstructed so that the modulator becomes aligned with the fiber opticline once every revolution of the spinner.
 141. The system of claim 140,wherein a pulse is reflected through the fiber optic line each time themodulator becomes aligned with the fiber optic line; and an acquisitionunit receives the reflected pulse and determines the velocity of thewellbore fluids based on the frequency of reception of the reflectedpulses.
 142. The sensor of claim 140, wherein the spinner includes ablade coupled to a disc.
 143. The sensor of claim 142, wherein the bladeis located external to the housing and the disc is located internal tothe housing.
 144. The sensor of claim 143, wherein the housing issealed.
 145. The sensor of claim 142, wherein the blade and the disc aremagnetically coupled across the housing.
 146. The sensor of claim 142,wherein the modulator is located on the disc.
 147. The sensor of claim146, wherein the modulator is located at a side of the disc.
 148. Thesensor of claim 139, wherein the optical signal is modulated byimparting a strain on the fiber optic line.
 149. The sensor of claim148, wherein the modulator comprises a fiber-bragg grating incorporatedon the fiber optic line.
 150. The sensor of claim 148, furthercomprising: a permanent magnet coupled to the spinner; a coil attachedto a housing; and wherein the permanent magnet and the coil becomemagnetically connected as the spinner revolves.
 151. The sensor of claim150, wherein the magnetic connection generates a voltage that causes apiezoelectric material mechanically coupled to the fiber optic line toconstrict and strain the fiber optic line.
 152. A method to calculatethe flow of fluid within a wellbore, comprising: providing a spinneradapted to spin when in contact with fluids flowing through thewellbore; and modulating an optical signal transmitted through a fiberoptic line depending on the spinning of the spinner wherein saidmodulation step comprises aligning a modulator with the fiber optic lineonce every revolution of the spinner.
 153. The method of claim 152,further comprising determining the velocity of the wellbore fluids basedon the frequency of modulations.
 154. A method to calculate the flow offluid within a wellbore, comprising: providing a spinner adapted to spinwhen in contact with fluids flowing through the wellbore; and modulatingan optical signal transmitted through a fiber optic line depending onthe spinning of the spinner wherein said modulation step comprisesimparting a strain on the fiber optic line.
 155. The method of claim154, wherein the imparting step comprises: creating a magneticconnection related to the revolution of the spinner; and generating avoltage that causes a piezoelectric material mechanically coupled to thefiber optic line to constrict and strain the fiber optic line.
 156. Acasing collar locator adapted to detect casing collars disposed in awellbore, comprising: a fiber optic line carrying an optical signal; amagnetic device adapted to become magnetically connected to a casingcollar as the magnetic device passes the casing collar; a modulator thatis functionally connected to the magnetic device; wherein the opticalsignal is modulated by the modulator when the magnetic device passes thecasing collar.
 157. The casing collar locator of claim 156, wherein themodulator is an optical interferometer.
 158. The casing collar locatorof claim 156, wherein the magnetic device brings the modulator intoalignment with the fiber optic line when the magnetic device passes acasing collar and the optical signal is modulated when the modulator isin alignment with the fiber optic line.
 159. The casing collar locatorof claim 158, wherein: a pulse is reflected through the fiber optic lineeach time the modulator becomes aligned with the fiber optic line; andan acquisition unit receives the reflected pulse and thereby identifiesthe detection of the casing collar.
 160. The casing collar locator ofclaim 156, wherein the optical signal is modulated by imparting a strainon the fiber optic line.
 161. The casing collar locator of claim 160,wherein the modulator comprises a fiber-bragg grating incorporated onthe fiber optic line.
 162. The casing collar locator of claim 160,wherein the magnetic device comprises a permanent magnet and a coil.163. The casing collar locator of claim 160, wherein the magneticconnection generates a voltage that causes a piezoelectric materialmechanically coupled to the fiber optic line to constrict and strain thefiber optic line.
 164. The casing collar locator of claim 156, whereinthe modulator moves in relation to the fiber optic line to cause themodulation of the optical signal.
 165. The casing collar locator ofclaim 164, wherein the magnetic device comprises a permanent magnet anda moving magnet and the moving magnet moves in relation to the permanentmagnet when the magnetic device passes the casing collar.
 166. Thecasing collar locator of claim 165, wherein movement of the movingmagnet causes the movement of the modulator in relation to the fiberoptic line.
 167. The casing collar locator of claim 166, wherein themoving magnet is biased to a stationary position by a spring.
 168. Thecasing collar locator of claim 166, wherein the modulator comprises acomponent having alternately placed black and white lines.
 169. A methodfor identifying the location of casing collars disposed in a wellbore,comprising: providing a magnetic device adapted to become magneticallyconnected to a casing collar as the magnetic device passes the casingcollar; and modulating an optical signal transmitted through a fiberoptic line when the magnetic device passes the casing collar.
 170. Themethod of claim 169, wherein the modulating step comprises aligning amodulator with the fiber optic line when the magnetic device passes thecasing collar.
 171. The method of claim 169, wherein the modulating stepcomprises imparting a strain on the fiber optic line.
 172. The method ofclaim 171, wherein the imparting step creating a magnetic connectionbetween the magnetic device and the casing collar when the magneticdevice passes the casing collar; and generating a voltage that causes apiezoelectric material mechanically coupled to the fiber optic line toconstrict and strain the fiber optic line.
 173. The method of claim 169,wherein the modulating step comprises comprises moving a modulator inrelation to the fiber optic line.
 174. The method of claim 173, whereinthe moving step comprises moving a moving magnet in relation to apermanent magnet when the magnetic device passes the casing collar. 175.The method of claim 174, further comprising biasing the moving magnet tostationary position by use of spring.